1. Field of the Invention
Embodiments of the present invention generally relate to artificially lifting fluid from a wellbore. More particularly, embodiments of the present invention relate to artificially lifting fluid from a wellbore using a gas lift system.
2. Description of the Related Art
To obtain hydrocarbon fluids from an earth formation, a wellbore is drilled into the earth to intersect an area of interest within a formation. The wellbore may then be “completed” by inserting casing within the wellbore and setting the casing therein using cement. In the alternative, the wellbore may remain uncased (an “open hole wellbore”), or may become only partially cased. Regardless of the form of the wellbore, production tubing is typically run into the wellbore primarily to convey production fluid (e.g., hydrocarbon fluid, which may also include water) from the area of interest within the wellbore to the surface of the wellbore.
Often, pressure within the wellbore is insufficient to cause the production fluid to naturally rise through the production tubing to the surface of the wellbore. Thus, to carry the production fluid from the area of interest within the wellbore to the surface of the wellbore, artificial lift means is sometimes necessary.
Some artificially-lifted wells are equipped with sucker rod lifting systems. Sucker rod lifting systems generally include a surface drive mechanism, a sucker rod string, and a downhole positive displacement pump. Fluid is brought to the surface of the wellbore by pumping action of the downhole pump, as dictated by the drive mechanism attached to the rod string.
One type of sucker rod lifting system is a rotary positive displacement pump, typically termed a progressive cavity pump (“PCP”). The progressive cavity pump lifts production fluid by a rotor disposed within a stator. The rotor rotates relative to the stator by use of a sucker rod string.
An additional type of sucker rod lifting system is a rod lift system, with which fluid is brought to the surface of the wellbore by reciprocating pumping action of the drive mechanism attached to the rod string. Reciprocating pumping action moves a traveling valve on the positive displacement pump, loading it on the down-stroke of the rod string and lifting fluid to the surface on the up-stroke of the rod string.
Sucker rod lifting systems include several moving mechanical components. Specifically, the rod strings of sucker rod lifting systems must be reciprocated or rotated to operate the lifting systems. In some applications, the moving parts are disadvantageous. When a subsurface safety valve is employed within the wellbore, such as within an offshore well, a sucker rod string cannot be placed through the subsurface safety valve. Additionally, moving parts are susceptible to failure or damage, potentially causing the sucker rod lifting systems to become inoperable.
An alternative lift system is a gas lift system. Gas lift systems are often the preferred artificial lifting systems because fewer moving parts exist during the operation of the gas lift systems than during the operation of sucker rod lift systems. Moreover, gas lift systems are sometimes preferred over sucker rod lift systems because no sucker rod is required in the operation of gas lift systems. Because a sucker rod is not used in operating the gas lift system, the gas lift system is usable in offshore wells having subsurface safety valves.
Two primary types of gas lift systems exist: tubing-retrievable gas lift systems and wireline-retrievable gas lift systems. Each type of gas lift system includes several gas lift valves, which are typically internal one-way valves spaced along the inner diameter of the production tubular. The gas lift valves allow fluid flow from an annulus between the casing and the production tubing to lift production fluid flowing through the production tubing, yet the gas lift valves prevent fluid flow from the longitudinal bore running through the production tubing into the annulus.
During the course of a gas lift operation, access to the gas lift valves by the operator is often necessary for several reasons. First, the gas lift valves typically require maintenance, repair, or replacement, for example if the valve is leaking fluid flow into the annulus from the production tubing bore. In fact, normal operations require repair or replacement of the gas lift valves every six months to one year of operation of the gas lift system. Second, altering the pressure settings of the gas lift valves, which is often required during a gas lift operation, requires access to the gas lift valves by the operator.
When tubing-retrievable gas lift systems are utilized, the entire production tubing string must be retrieved from the wellbore to allow access to the gas lift valves for repair, maintenance, replacement, or changing of the pressure settings of the gas lift valves, because the production tubing and gas lift valves are integral to one another. In contrast, wireline-retrievable gas lift systems permit retrieving of the gas lift valves from the wellbore using wireline without necessitating the removal of the production tubing from the wellbore. Removing the entire production tubing from the wellbore is costly and inefficient; therefore, wireline-retrievable gas lift systems are often the preferred type of gas lift system, especially when the gas lift system is used offshore or in remote locations where rig interventions are expensive.
A typical wireline-retrievable gas lift system 10 is shown in FIG. 1. Generally, compressed gas G is injected into an annulus 15 between an outer diameter of a production tubing string 20 and the inner diameter of casing 25 within the wellbore 30. A valve system 35 supplies injection gas G and allows produced fluid to exit the gas lift system 10.
Spaced within the production tubing string 20 are side pocket mandrels 40 having gas lift valves 45 within side pockets 90 thereof, the side pockets 90 of the side pocket mandrels 40 being offset from the centerline of the production tubing string 20. The gas lift valves 45 are one-way valves used to allow gas flow from the annulus 15 into the production tubing string 20 and to disallow gas flow from the production tubing string 20 into the annulus 15.
A production packer 50 located at a lower end of the production tubing string 20 forces the flow of production fluid P from a reservoir or zone of interest in a formation 55 up through the production tubing string 20 instead of up through the annulus 15. Additionally, the production packer 50 forces the gas flow from the annulus 15 into the production tubing string 20 through the gas lift valves 45, as gas G is not allowed to flow further down into the annulus 15 past the production packer 50.
In operation, production fluid P flows from the formation 55 into the wellbore 30 through perforations 60 through the casing 25 and the formation 55. The production fluid P flows into the production tubing string 20. When it is desired to lift the production fluid P with gas G, compressed gas G is introduced into the annulus 15. The gas lift valves 45 allow the gas G to flow into the production tubing string 20 while preventing the flow of the production fluid P into the annulus 15 through the gas lift valves 45.
FIG. 1A shows a section of a typical wireline-retrievable production tubing string 20 having a side pocket mandrel 40 therein. The gas lift valve within the side pocket 90 of the side pocket mandrel 40 is not shown in FIG. 1A. A first slot 67 through a wall of the side pocket mandrel 40 exists below the gas lift valve on one side of the wall of the side pocket 90 of the side pocket mandrel 40, and a second slot 69 through a wall of the production tubing 20 exists above the gas lift valve on the opposite side of the wall of the side pocket 90.
Referring to both FIGS. 1 and 1A, compressed gas G introduced into the annulus 15 flows through each first slot 67 into each side pocket 90, through each gas lift valve 45, and then out each side pocket 90 through each second slot 69 into the bore of the production tubing string 20. The gas flow into the bore of the production tubing string 20 helps lift the production fluid P to the surface of the wellbore 30 by lowering the density of the production fluid P. Also, the injected gas G lowers the hydrostatic pressure in the production tubing 20 to re-establish the required pressure differential between the reservoir and the wellbore 30, thereby causing the production fluid P to flow to the surface of the wellbore 30. At the same time, the gas lift valves 45 prevent fluid flow through the side pockets 90 in the direction from the production tubing string 20 bore into the annulus 15.
At various times during the gas lift operation, the gas lift valve must be removed for repair, maintenance, and/or changing of pressure settings of the gas lift valve. Moreover, the gas lift valve may fail or leak during the gas lift operation. Removal of the gas lift valve from the production tubing and/or failing or leaking of the gas lift valve are problematic because the gas lift valve is no longer present within the side pocket mandrel or is no longer effective to prevent fluid flow from the production tubing into the annulus. Therefore, production fluid flowing up from the reservoir through the production tubing string is allowed to flow into the annulus unhindered through the side pockets of the side pocket mandrels.
The presence of production fluid in the annulus is problematic for several reasons. First, the production fluid is corrosive to the casing surrounding the production tubing string and may therefore cause corrosion damage to the casing. Second, the production fluid existing within the annulus increases the fluid pressure present within the annulus, possibly increasing to sufficient pressure levels to cause damage to the casing surrounding the production tubing string. Damaging the casing could cause the production fluid to leak back into the formation through holes in the casing, resulting in loss of valuable production fluid as well as becoming an environmental hazard. Repairing this damage to the casing is very expensive, especially in the form of loss of production during the repair time, as the production tubing string and other gas lift equipment must be removed from the wellbore and a casing section or casing patch must be re-installed within the wellbore over the damaged portion of the casing.
Additionally, the presence of production fluid in annulus is problematic because, even without resulting damage to the casing, time-consuming preparatory activities must be carried out before the gas lift operation may resume after re-installing the gas lift valves within the side pockets of the side pocket mandrels. One especially time-consuming operation which must be accomplished prior to resuming the gas lift operation involves unloading the production fluid present within the annulus from the wellbore. Unloading the well, if production fluid is present within the production tubing as well as within the annulus, often takes twelve hours or more every time the gas lift valves must be removed from the production tubing. Unloading the production fluid from the annulus typically consumes 8–9 hours of that unloading time. This time required to unload the annulus prior to any further gas lift operation wastes valuable production time, decreasing the profitability of the well.
Therefore, it would be advantageous to provide a gas lift system which reduces damage to the surrounding casing when the gas lift valve is ineffective and/or is removed from the production tubing. It would be further advantageous to provide a gas lift system which decreases the time necessary to unload the well prior to resuming a gas lift operation when the gas lift valve is ineffective and/or is removed from the production tubing. Furthermore, it would be beneficial to provide a gas lift system and operation capable of preventing flow of production fluid into the annulus when the gas lift valve is ineffective and/or is removed from the production tubing.